The pipeline bundle, with the LEOS tube secured between the pipes to prevent it being snagged or crushed between the pipe lowering-in rollers, is lowered into place (Fig. 7).
There were minimal logistical difficulties with installing the LEOS tube as part of the bundle and the LEOS tube caused no logistical difficulties to the pipeline welding or field jointing activities. When the completed pipeline bundle was ready for lowering, the LEOS tube was secured between the pipes so that it would not snag or be crushed between the pipe lowering-in rollers (Fig. 7).
Shore crossing; island
The subsea-to-aboveground transition is critical for the pipeline, as can be seen from the vertical transition riser for the pipeline. The transition at the shore crossing introduces the added complication of long-term pipeline movement in the vertical and horizontal planes due to pipe thermal growth and long-term thaw settlement.
The pipelines make this transition in a vertical riser shaft that acts as a sleeve around the pipes, leaving them free to move when they warm up. Here, the LEOS tube is firmly strapped between the pipes to protect it from differential loads due to the soil backfill surcharge.
A layer of select backfill gravel was placed under the pipe so that when thawing occurs the settlement will be within acceptable limits (up to 1 ft under the vertical riser). Elsewhere, through the lagoon area out to Stump Island, permafrost is encountered, and differential settlement of up to 2 ft is accounted for by the design. Most of the thawing will take place within the first 2-3 years of operation.
The pipeline will be monitored with internal-inspection tools to measure pipe geometry to determine the extent of movement. Since the Young's Modulus for PEX is many times smaller than for steel, any anticipated pipe movement should pose no risk for the LEOS tube.
Likewise, beyond the lagoon in the portion of the route potentially exposed to the deepest ice keel gouging (6-ft trench depth of cover), the tube will remain between the pipes. If any movement should occur, it would be limited to the extent of pipe movement.
The tube is strapped to the pipeline and must negotiate two right-angled bends within the vertical riser shaft. These are 5-D (1.3 m radius) bends subjecting the tubing to its severest bending.
The LEOS tube transitions out of the vertical riser at the shore through a sleeve insert into the PEX armor tube. Once above ground, the LEOS tube is no longer perforated and as soon as it exits the riser shaft, the LEOS PVDF tubing is changed to 0.5-in. diameter stainless steel tubing via a custom designed coupling.
A protective shroud was designed to prevent inquisitive bears accessing the coupling and the plastic LEOS tube. After exiting the riser shaft, the stainless steel tubing is routed along the gas line and via a 2-in. fuel-gas-line takeoff over to the remote terminal unit (RTU) building.
An insulated metal box is provided under the building to store a 300-m length of LEOS buffer tubing before the stainless steel tube enters the RTU building where it is hooked up to the TPG cabinet.
The buffer tubing, which is not perforated, serves as a virtual length of uncontaminated air (i.e., no traces of background methane or other exhaust contaminants). This buffer length cues the measurement system to the arrival of the hydrogen test peak.
Fresh air is drawn into the TPG cabinet via an inlet diffuser mounted on the outside wall of the RTU building. The air-inlet diffuser is to prevent snow from blocking the air intake line. The air is passed through an activated-carbon filter and desiccant jar before traveling into the LEOS sensor tube.
The transition into the Northstar production island differs from the shore crossing.
Instead of the vertical riser used at the shore crossing, the pipeline transitions into the island with a sweeping vertical curve equal to the slack radius of the steel pipeline. The pipeline enters the island under a sheet piled steel wall.
The transition from subsea to above ground requires that the tube be heat traced to prevent water vapor condensation inside the tube. Although the rate of diffusion of water across the acetate membrane is very slight, over the 10-km length of the tube this could accumulate if there were a vacuum-pump breakdown or power outage for a longer period (several weeks).
As a precaution, heat tracing was applied at the waterline all the way to the measurement module. The LEOS tube was terminated approximately 4 ft below the level of the dock at elevation +10 ft and transitioned with 0.5-in. TPE (reinsulated stainless steel tubing with self regulating electric tracing).
Pre-operation; checks
The sealift logistics for piping-module delivery to the production island made it necessary to install the LEOS system in two phases, 12 months apart.
The LEOS tube was installed during the pipeline installation prior to the first-year sealift of drilling production modules from Anchorage to the island in summer 2000. The TPG cabinet in the RTU building at the shore crossing was also installed during Phase 1, although there was no power during the next 12 months.
Since the tube should not be left underwater for more than a few weeks without evacuating the air, it was also necessary to hook-up a temporary air-pump module at the production island so that air inside the tube could be periodically evacuated. This was required so that moisture resulting from water vapor would not become trapped inside the tube before the system was made operational.
Construction Phase 2 in summer 2001 (prior to production start) included powering up the TPG cabinet at the shore crossing, hooking-up the LEOS tube with stainless steel tubing on the island, and starting up the measuring station inside the warehouse on Seal Island. Due to the many construction activities on the island, it was necessary to move the air-pump module several times during the 2 years following Phase 1 installation.
The LEOS tube was pressurized and depressurized daily as precaution until a temporary air pump was hooked up.
After the air pump was installed, a system functional check was made at the end of June 2000. At that time, background methane levels along the pipeline route were also measured. During the summer months, access to the shore crossing is limited to a water route. Therefore, servicing of components is not readily achievable.
The battery pack that provides energy for the hydrolysis to generate the hydrogen test peak has a 1-year life. Other components within the TPG cabinet include the activated-carbon filter and desiccant which are factory installed and require only annual servicing.
Periodic checks were necessary to ensure that the pump is working normally (every 7 days).
Before pipeline start-up, technicians visited the site to check on the system using a portable LEOS measuring device. The system was fully functional and the results of the test trace output were interesting.
Many hydrogen spikes can be seen corresponding closely to the sacrificial anodes attached to the pipe for cathodic protection. The anodes function electrolytically, and hydrogen is evolved through the electrolytic process due to the seawater reacting with the aluminum bracelet. This is not a surprising result and the possibility was envisioned during conceptual design.
The extent of this was not quantified, however. The presence of the hydrogen spikes is a nuisance because it masks the single calibration spike that is an important feature of the LEOS system. A selective catalytic converter has been installed that oxidizes the hydrogen to water vapor so that anode-generated hydrogen spikes no longer register at the measurement station.
More recently, a modem link enables Framatome technicians remotely to monitor the daily outputs and advise the operating staff regarding the significance of a changing indication.
After a year of operation, the LEOS system has been field calibrated to account for increasing background methane due to soil warming. The evolution of hydrogen from the sacrificial anodes has been remedied by insertion of a catalytic converter module ahead of the measurement station, thereby preventing false alarms.
The ability to detect the hydrogen from all the anodes demonstrates that the cathodic protection system is functioning. It also enables individual anodes to be discerned and provides an opportunity to improve the accuracy of a potential leak location.
Acknowledgments
The authors thank BP Exploration (Alaska) Inc., INTEC Engineering Inc., and Framatome ANP for permission to publish this article.
References
- Braden, A., Manikin, V., Rice, D., Swank, G, Hinnah, D., Monkelien, K. and Walker, J., "First Arctic Subsea Pipeline Moving to Reality," 1998 Offshore Technology Conference, Houston; Paper No. 8717.
- Hovey, D. J., and Farmer, E.J., DOT Stats indicates need to refocus pipeline accident prevention, OGJ, Mar. 15, 1999. p. 52.
- US ACE, Final Environmental Impact Statement; 1999 Beaufort Sea Oil and Gas Development/Northstar Project, US Army Corps of Engineers, Alaska District, Anchorage.
- Issel, Wolfgang R. J., and Swiger, P., "LASP – A Leakage Alarm System for Pipelines," Pipeline Industry, June 1985.
- Lanan, G. A., Nogueira, A. C., McShane, B. M., and Ennis, J. O., ''Northstar Development Project Pipelines Description and Environmental Loadings'', International Pipeline Conference, May 2000, Calgary.
Based on a presentation to the International Pipeline Conference (ASME), Sept. 29—Oct. 3, 2002, Calgary.
